EP1474218B1 - Procede d'elimination de dioxyde de carbone de melanges de gaz - Google Patents

Procede d'elimination de dioxyde de carbone de melanges de gaz Download PDF

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Publication number
EP1474218B1
EP1474218B1 EP03709686A EP03709686A EP1474218B1 EP 1474218 B1 EP1474218 B1 EP 1474218B1 EP 03709686 A EP03709686 A EP 03709686A EP 03709686 A EP03709686 A EP 03709686A EP 1474218 B1 EP1474218 B1 EP 1474218B1
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Prior art keywords
amine
parts
process according
mol
amount
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EP03709686A
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German (de)
English (en)
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EP1474218A1 (fr
Inventor
Theodorus Johannes Brok
Rudolf Johannes Mathilda Groenen
Jeanine Marie Klinkenbijl
Mariette Catharina Knaap
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Shell Internationale Research Maatschappij BV
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Shell Internationale Research Maatschappij BV
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    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1493—Selection of liquid materials for use as absorbents
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02C—CAPTURE, STORAGE, SEQUESTRATION OR DISPOSAL OF GREENHOUSE GASES [GHG]
    • Y02C20/00—Capture or disposal of greenhouse gases
    • Y02C20/40—Capture or disposal of greenhouse gases of CO2

Definitions

  • the present invention relates to a process for removing carbon dioxide and optionally hydrogen sulphide and/or COS from a gas stream containing these compounds by washing the gas with an aqueous washing solution containing water, sulfolane and a secondary or tertiary amine derived from ethanol amine.
  • the invention further relates to an absorbent liquid to be used in the above process.
  • organic solvents or aqueous solutions of organic solvents for removing of so-called acidic gasses as carbon dioxide and optionally hydrogen sulphide and/or COS from a gas stream containing these compounds has been described long ago. See for instance A.L. Kohl and F.C. Riesenfeld, 1974, Gas Purification, 2nd edition, Gulf Publishing Co. Houst on and R.N. Maddox, 1974, Gas and Liquid Sweetening, Campbell Petroleum Series .
  • a regenerable absorbent solvent is used in a continuous process.
  • WO-A-0 066 249 describes absorbent compositions for removal of acid gases from gas streams.
  • Chemical solvents which have proved to be industrially useful are primary, secondary and/or tertiary amines derived alkanolamines.
  • the most frequently used amines are derived from ethanolamine, especially monoethanol amine (MEA), diethanolamine (DEA), triethanolamine (TEA), diisopropanolamine (DIPA) and methyldiethanolamine (MDEA).
  • Physical solvents which have proved to be industrially suitable are cyclo-tetramethylenesulfone and its derivatives, aliphatic acid amides, N-methylpyrrolidone, N-alkylated pyrrolidones and the corresponding piperidones, methanol, ethanol and mixtures of dialkylethers of polyethylene glycols.
  • a well-known commercial process uses an aqueous mixture of a chemical solvent, especially DIPA and/or MDEA, and a physical solvent, especially cyclotetra-methylene-sulfone.
  • a chemical solvent especially DIPA and/or MDEA
  • a physical solvent especially cyclotetra-methylene-sulfone.
  • carbon dioxide may be flashed at a relatively high pressure when compared with similar, aqueous chemical absorbents. This reduces re-compression requirements, e.g. for re-injection. This holds especially for the combination of DEA, TEA, DIPA and MDEA, especially DIPA and MDEA, and piperazine.
  • the present invention therefore, relates to a process for the removal of carbon dioxide and optionally hydrogen sulphide and/or COS from a gas stream containing these compounds by washing the gas with an aqueous washing solution containing between 15 and 45 parts by weight based on total solution, preferably between 15 and 40 parts by weight, of water, between 15 and 40 parts by weight based on total solution of sulfolane and between 30 and 60 parts by weight based on total solution of a secondary or tertiary amine derived from ethanol amine, the amounts of water, sulfolane and amine together being 100 parts by weight, the process being carried out in the presence of a primary or secondary amine compound in an amount between 0.5 and 15 wt%, preferably between 0.5 and 10 wt%, based on water, sulfolane and amine.
  • the carbon dioxide absorption rate is faster, the loading amount is higher, the solvent/gas ratio is lower, the design of the plant is smaller and the regeneration heat requirement is lower (resulting is less cooling capacity).
  • the addition of sulfolane results in the possibility to produce carbon dioxide at intermediate pressures, e.g. pressures between 3 and 15 bara, preferably between 5 and 10 bara.
  • the gases to be treated in the process according to the present invention may be synthesis gas, obtained for instance by (catalytic) partial oxidation and/or by steam methane reforming of hydrocarbons, e.g. methane, natural or associated gas, naphtha, diesel and liquid residual fractions, gases originating from coal gasification, coke oven gases, refinery gases, hydrogen and hydrogen containing gases, and is especially synthesis gas or natural gas.
  • hydrocarbons e.g. methane, natural or associated gas, naphtha, diesel and liquid residual fractions
  • gases originating from coal gasification, coke oven gases, refinery gases, hydrogen and hydrogen containing gases e.g. methane, natural or associated gas, naphtha, diesel and liquid residual fractions
  • gases originating from coal gasification e.g. methane, natural or associated gas, naphtha, diesel and liquid residual fractions
  • gases originating from coal gasification e.g. methane, natural or associated gas, naphtha, diesel and liquid residual fraction
  • the amounts of acidic gaseous compounds may range from a few tenth of a percent up to 70 or even 80 vol% of the total gas stream.
  • the amount of carbon dioxide is between 1 and 45 mol%, preferably between 5 and 25 mol%
  • the amount of hydrogen sulphide is between 0 and 25 mol%, preferably between 0 and 10 mol%
  • the amount of COS is between 0 and 2 mol% (all % based on total gas stream).
  • the amount of water is preferably between 20 and 45 parts by weight, the amount of sulfolane is preferably between 20 and 35 parts by weight and the amount of amine is preferably between 40 and 55 parts by weight, the amounts of water, sulfolane and amine together being 100 parts by weight.
  • the preferred ranges results in optimum carbon dioxide removal in most cases.
  • the amine derived from ethanol amine may be a single secondary or tertiary amine derived from ethanol amine or mixtures of secondary amines and/or tertiary amines.
  • Suitable amines are secondary amines derived from ethanol amine which ethanol amine may or may not be substituted at one or both carbon atoms. Preferably the ethanol amine is not substituted or substituted at one carbon atom.
  • Suitable substituents are C 1-4 alkyl groups, preferably methyl or ethyl groups, more preferably methyl. The amine group is substituted by a C 1-4 alkyl group, which group is optionally substituted by a hydroxyl group. Preferred amine substituent groups are methyl, 2-(1-hydroxyethyl) and 1-(2-hydroxypropyl).
  • Very suitable amines are DIPA, DEA or MMEA, preferably DIPA.
  • Suitable amines are tertiary amines derived from ethanolamine which ethanolamine may or may not be substituted at one or both carbon atoms. Preferably the ethanolamine is not substituted or substituted at one carbon atom.
  • Suitable substituents are C 1-4 alkyl groups, preferably methyl or ethyl groups, more preferably methyl.
  • the second substituents may be chosen from the same group as the first substituent.
  • the third substituent of the amine group is a C 1-4 alkyl group, which group is optionally substituted by a hydroxyl group.
  • Preferred amine substituent groups are methyl, 1-(2-hydroxyethyl) and 1-(2-hydroxypropyl).
  • Very suitable amines are MDEA or DEMEA, preferably MDEA.
  • the primary or secondary amine compound has suitably a pKb (at 25 °C in water) below 5.5, preferably below 5, more preferably below 4.5.
  • a lower pKb results in improved process results in the form of increased CO 2 absorption.
  • the primary or secondary amine compound to be added to the absorption solution suitably reacts faster with carbon dioxide under the same conditions than the amine reacts with carbon dioxide.
  • the primary or secondary amine compound reacts at least twice as fast with carbon dioxide then the amine reacts with carbon dioxide, the reaction velocity being defined as the reaction velocity constant (at 25 °C).
  • the primary or secondary amine compound reacts five times as fast as the amine, still more preferably reacting twenty times as fast as the amine. It is preferred to use in the case of a secondary amine a primary amine compound, and in the case of a tertiary amine a primary or secondary amine.
  • Very suitable compounds are piperazine, methyl ethanol amine, or (2-aminoethyl)-ethanol amine, especially piperazine.
  • the amount of primary or secondary amine compound will usually be between 0.5 and 15 wt% based on water, sulfolane and amine, preferably between 1 and 10 wt%, more preferably about 4 wt%.
  • the amount of primary or secondary amine compound is suitably at least 0.8 mol/l, especially between 1.0 mol/l and 3.0 mol/l, more especially between 1.0 mol and 3.0 mol/l, especially piperazine.
  • a preferred embodiment is the use of 0.7-0.9 mol/l of piperazine, especially 0.6-0.8 mol/l.
  • the process according to the present invention is suitably carried out at a temperature between 15 and 90 °C, preferably at a temperature of at least 20 °C, more preferably between 25 and 80 °C, still more preferably between 40 and 65 °C, and even still mote preferably at about 55 °C.
  • the process is suitably carried out at a pressure between 10 and 150 bar, especially between 25 and 90 bara.
  • the invention will usually be carried out as a continuous process, which process also comprises the regeneration of the loaded solvent.
  • the contacting of the gas mixture with the absorbent solvent is well known in the art. It is suitably carried out in a zone having from 5-80 contacting layers, such as valve trays, bubble cap trays, baffles and the like. Structured packing may also be applied.
  • the amount of CO 2 removal can be optimised by regulating the solvent/gas ratio.
  • a suitable solvent/gas ratio is from 1.0 to 10 (w/w), preferably between 2 and 6.
  • the loaded solvent may contain beside CO 2 and optionally H 2 S and/or COS appreciable amounts of other compounds from the gas mixture to be purified, e.g. hydrocarbons, carbon monoxide, hydrogen etc.
  • the loaded solvent may advantageously flashed in a second step to a pressure which is below the partial pressures of CO 2 and optionally H 2 S and COS at the prevailing temperature.
  • the flash is carried out at a pressure between 1 and 15 bara, preferably between 1 and 10 bara, more preferably ambient pressure. In the gas set free during the flashing large amounts of the carbon dioxide and optionally H 2 S and/or COS are present.
  • the loaded solvent optionally after flashing as described above is regenerated at a relatively high temperature suitably at a pressure between 1 and 2 bara.
  • the regeneration is suitably carried out by heating in a regeneration column, suitably at a temperature between 70 and 150 °C. The heating is preferably carried out with steam or hot oil.
  • the lean absorbent solvent will be used again in the absorption stage described before.
  • the lean solvent is heat exchanged with the loaden solvent.
  • the invention further relates to an absorbent solvent containing between 15 and 45 parts by weight based on total solution, preferably between 15 and 40 parts by weight, of water, between 15 and 40 parts by weight based on total solution of sulfolane and between 30 and 60 parts by weight based on total solution of a secondary or tertiary amine derived from ethanol amine, the amounts of water, sulfolane and amine together being 100 parts by weight and a primary or secondary amine compound in an amount between 0.5 and 15 wt% based on water, sulfolane and amine.
  • the preferred individual compounds of the absorbent solvent and the ranges in the solvent are similarly defined as in the way as has been done for the process as described above.
  • a stream of natural gas comprising 11.9 vol% carbon dioxide was washed with an absorbent solution comprising 35 wt% MDEA, 18 wt% sulfolane and 43 wt% water.
  • a commercially available standard absorber was used.
  • the carbon dioxide was removed until a level of 3.1 vol%.
  • Addition of 1 wt% piperazine resulted in a further reduction of the amount of carbon dioxide ((1.7 vol%).
  • Addition of another 1 wt% piperazine resulted in a further reduction of carbon dioxide (1.3 vol%).

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  • Chemical & Material Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Analytical Chemistry (AREA)
  • General Chemical & Material Sciences (AREA)
  • Oil, Petroleum & Natural Gas (AREA)
  • Chemical Kinetics & Catalysis (AREA)
  • Gas Separation By Absorption (AREA)
  • Treating Waste Gases (AREA)
  • Industrial Gases (AREA)

Claims (16)

  1. Procédé d'élimination du dioxyde de carbone et éventuellement du sulfure d'hydrogène et/ou du COS d'un courant de gaz contenant ces composés en lavant le gaz avec une solution de lavage aqueuse contenant 15 à 45 parties en poids, par rapport à la solution totale, d'eau, 15 à 40 parties en poids, par rapport à la solution totale, de sulfolane et 30 à 60 parties en poids, par rapport à la solution totale, d'une amine secondaire ou tertiaire dérivée de l'éthanolamine, les quantités d'eau, de sulfolane et d'amine représentant conjointement 100 parties en poids, le procédé étant effectué en présence d'un composé d'amine primaire ou secondaire en quantité de 0,5 à 15 % en poids par rapport à l'eau, au sulfolane et à l'amine.
  2. Procédé selon la revendication 1, dans lequel le courant de gaz est du gaz naturel ou un gaz de synthèse.
  3. Procédé selon la revendication 1 ou 2, dans lequel la quantité de dioxyde de carbone se situe entre 1 et45 % en mole, de préférence entre 5 et 25 % en mole, la quantité de sulfure d'hydrogène se situe entre 0 et 25 % en mole, de préférence entre 0 et 10 % en mole et la quantité de COS se situe entre 0 et 2 % en mole (tous les % étant basés sur le courant de gaz total).
  4. Procédé selon l'une quelconque des revendications 1 à 3, dans lequel la quantité d'eau se situe entre 20 et 45 parties en poids, la quantité de sulfolane se situe entre 20 et 35 parties en poids et la quantité d'amine se situe entre 40 et 55 parties en poids, les quantités d'eau, de sulfolane et d'amine représentant conjointement 100 parties en poids.
  5. Procédé selon l'une quelconque des revendications 1 à 4, dans lequel l'amine secondaire dérivée de l'éthanolamine est la DIPA, la DEA ou la MMEA, de préférence la DIPA.
  6. Procédé selon l'une quelconque des revendications 1 à 4, dans laquelle l'amine tertiaire dérivée de l'éthanolamine est la MDEA ou la DEMEA, de préférence la MDEA.
  7. Procédé selon l'une quelconque des revendications 1 à 6, dans lequel le composé d'amine primaire ou secondaire a un pKb (à 25 °C dans de l'eau) de moins de 5, de préférence de moins de 4,5.
  8. Procédé selon l'une quelconque des revendications 1 à 6, dans lequel le composé d'amine primaire ou secondaire réagit avec le dioxyde de carbone au moins deux fois plus vite que l'amine réagit avec le dioxyde de carbone, la vitesse de réaction étant définie par la constante de vitesse réactionnelle (à 25 °C), et le composé d'amine primaire ou secondaire réagissant de préférence cinq fois plus vite que l'amine, mieux encore vingt fois plus vite que l'amine.
  9. Procédé selon l'une quelconque des revendications 1 à 8, dans lequel le composé d'amine primaire ou secondaire est la pipérazine, la méthyl-éthanolamine ou la (2-aminoéthyl)éthanolamine, en particulier la pipérazine.
  10. Procédé selon l'une quelconque des revendications 1 à 9, dans lequel la quantité de composé d'amine primaire ou secondaire se situe entre 2,5 et 10 % en poids.
  11. Procédé selon l'une quelconque des revendications 1 à 10, dans lequel la quantité de composé d'amine primaire ou secondaire est d'au moins 0,8 mole/l, en particulier entre 1,0 mole/l et 3,0 moles/l, plus spécifiquement entre 1,0 mole et 3,0 moles de pipérazine/l.
  12. Procédé selon l'une quelconque des revendications 1 à 11, dans lequel le procédé est effectué à une température d'au moins 20 °C, de préférence entre 25 et 90 °C, mieux encore entre 40 et 65 °C,à une pression absolue entre 25 et 90 bars.
  13. Procédé selon l'une quelconque des revendications 1 à 12, lequel procédé comprend également une régénération du solvant chargé.
  14. Procédé selon l'une quelconque des revendications 1 à 13, dans lequel le procédé est effectué à une pression absolue entre 25 et 90 bars, dans lequel procédé le solvant chargé est soumis à une vaporisation éclair à une pression absolue entre 1 et 15 bars, suivie d'une régénération à une pression absolue entre 1 et 2 bars.
  15. Liquide absorbant contenant 15 à 45 parties en poids, par rapport à la solution totale, d'eau, 15 à 40 parties en poids, par rapport à la solution totale, de sulfolane et 30 à 60 parties en poids, par rapport à la solution totale, d'une amine secondaire ou tertiaire dérivée de l'éthanolamine, les quantités d'eau, de sulfolane et d'amine représentant conjointement 100 parties en poids et un composé d'amine primaire ou secondaire en quantité de 0,5 à 15 % en poids par rapport à l'eau, au sulfolane et à l'amine.
  16. Liquide absorbant selon la revendication 15, les composés individuels étant en outre définis selon les revendications 4, 5, 6, 7, 8, 9, 10 ou 11.
EP03709686A 2002-01-14 2003-01-14 Procede d'elimination de dioxyde de carbone de melanges de gaz Expired - Lifetime EP1474218B1 (fr)

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EP02075133 2002-01-14
EP02075133 2002-01-14
PCT/EP2003/000338 WO2003057348A1 (fr) 2002-01-14 2003-01-14 Procede d'elimination de dioxyde de carbone de melanges de gaz
EP03709686A EP1474218B1 (fr) 2002-01-14 2003-01-14 Procede d'elimination de dioxyde de carbone de melanges de gaz

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EP1474218A1 EP1474218A1 (fr) 2004-11-10
EP1474218B1 true EP1474218B1 (fr) 2008-12-10

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US (1) US7758673B2 (fr)
EP (1) EP1474218B1 (fr)
JP (1) JP2005514194A (fr)
CN (1) CN100379485C (fr)
AU (1) AU2003214041B2 (fr)
BR (1) BR0306705B1 (fr)
CA (1) CA2473064C (fr)
DE (1) DE60325171D1 (fr)
ES (1) ES2316734T3 (fr)
NO (1) NO334582B1 (fr)
NZ (1) NZ533691A (fr)
WO (1) WO2003057348A1 (fr)

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CN1615173A (zh) 2005-05-11
ES2316734T3 (es) 2009-04-16
NO20043667L (no) 2004-08-12
US20050166756A1 (en) 2005-08-04
BR0306705A (pt) 2004-12-28
US7758673B2 (en) 2010-07-20
WO2003057348A1 (fr) 2003-07-17
DE60325171D1 (de) 2009-01-22
AU2003214041A1 (en) 2003-07-24
AU2003214041B2 (en) 2008-10-02
CN100379485C (zh) 2008-04-09
JP2005514194A (ja) 2005-05-19
NZ533691A (en) 2006-11-30
BR0306705B1 (pt) 2011-10-04
CA2473064A1 (fr) 2003-07-17
EP1474218A1 (fr) 2004-11-10
NO334582B1 (no) 2014-04-14
CA2473064C (fr) 2011-11-29

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